Hydrocarbons, such as oil and gas, may be recovered from various types of subsurface geological formations. A well is drilled through the earth until the hydrocarbon bearing formation is reached. Hydrocarbons, at least ideally, then are able to flow from the porous formation into the well.
That is true for some subsurface formations, such as sandstone, which are very porous. Hydrocarbons are able to flow easily from the formation into a well. Other formations, however, such as shale rock, limestone, and coal beds, are only minimally porous. The formation may contain large quantities of hydrocarbons, but production through a conventional well may not be commercially practical because hydrocarbons flow though the formation and collect in the well at very low rates. The industry, therefore, relies on various techniques for improving the well and increasing production from formations which are relatively nonporous.
One technique involves drilling a well in a horizontal direction, so that the borehole extends along a formation instead of passing through it. More of the formation is exposed to the borehole, and the average distance hydrocarbons must flow to reach the well is decreased. Another technique involves creating fractures in a formation which will allow hydrocarbons to flow more easily. Indeed, the combination of horizontal drilling and fracturing, or “frac'ing” or “fracking” as it is known in the industry, is presently the only commercially viable way of producing natural gas from the vast majority of North American gas reserves.
Fracturing is most commonly accomplished by using “frac” pumps to inject a fracturing fluid into a well at extremely high rates. Fluid is pumped into the well until it creates pressure high enough to fracture the formation. The fluid typically includes a proppant, such as grains of sand, ceramic or other particulates, that prevents the fractures from closing when pumping is stopped, thus creating flow paths for hydrocarbons-through the formation.
A frac pump may operate at fluid pressures up to 18,000 psi or more and at flow rates of 2 to 3 thousand gpm. Moreover, the proppant which typically is carried by the injection fluid is extremely abrasive. Given those operating conditions frac pumps necessarily incorporate a number of wear elements or consumables such as plungers, valves, and packings, which must be replaced periodically.
The harsh operating conditions and frequent servicing means that the typical fracturing operation rarely relies on a single pump. It is important that the operation continue uninterrupted once it has been initiated. If there is a significant pressure drop before the required volume of proppant has been injected into a formation, the formation will tend to relax and close the fractures. Operators, therefore, typically use an array of frac pumps connected in parallel to a common flow line. The array provides excess capacity so that, if necessary, individual pumps may be taken off-line for repair or service without having to stop the overall operation. That excess capacity, however, has its own cost, which can be reduced only to the extent that the likelihood of any individual pump failing or requiring service during the frac operation is reduced.
Reducing the likelihood of pump failure or servicing during frac operations, however, is increasingly difficult. Frac jobs have become more extensive, both in terms of the pressures required to fracture a formation and the time required to complete all stages of an operation. For example, prior to horizontal drilling, a typical vertical well might require fracturing in only one, two or three zones at pressures usually well below 10,000 psi. Pumps were only required to operate for a few hours at a time and could be returned to a repair facility for service between operations.
Fracturing a horizontal well, however, may require fracturing in 20 or more zones. Thus, fracturing horizontal wells in shale formations such as the Eagle Ford shale in South Texas typically requires pressures of at least 9,000 psi and 6 to 8 hours or more of pumping. Horizontal wells in the Haynesville shale in northeast Texas and northwest Louisiana require pressures of around 13,500 psi. Pumps also may be required to operate near continuously for several days before fracturing is complete. That has led operators in the Haynesville shale to provide up to 50% excess pumping capacity.
Unfortunately, when a pump is operated at high power for extended periods of time, threaded nuts and covers designed to provide access to pump consumables may tend to loosen. The problem is exacerbated because many of the nuts and other threaded bodies have relatively large diameters. Some loosening may be tolerated, but excessive loosening has various consequences. At the least, it requires that operators constantly monitor and retighten all of the many threaded nuts and covers on a pump. Otherwise, a threaded nut or cover may loosen to the point where fluid is discharged from the pump. It also is possible for a loosened nut or cover to come into contact with moving parts of the pump and cause significant damage to the pump.
Thus, workers in the art have proposed various mechanisms to lock such threaded closures in place. For example, U.S. Publ. Pat. Appl. No. 2010/0,143,163 of P. Patel et al. discloses a packing nut lock and an access bore cover locking assembly which are designed for use with a typical frac pump. Such pumps are reciprocating plunger pumps having a number of plungers, usually three (a “triplex” pump) or five (a “quintiplex” pump). The plungers move back and forth in a cylinder, traveling in and out of a pump chamber. A fluid tight seal is provided between the cylinder and the plunger by a packing element. The pump chamber has an intake port and a discharge port. Each port has a one-way valve. Thus, fluid enters the chamber through the intake port as the plunger withdraws from the chamber and is pumped out of the chamber through the discharge port as the plunger enter the chamber.
The pump is constructed so that its packing elements, valves, and other wear components may be accessed relatively easily. For example, the plunger packing is mounted in a slightly enlarged, rear portion of the cylinder and is held in place by a threaded, annular nut which screws into the cylinder block. The nut may be removed to provide access to the packing so that it may be replaced as needed. Similarly, bores are provided in the cylinder block which allow access to the intake and discharge port valves so that they may be replaced. Those access bores are sealed with plugs that are held in place by threaded covers.
The packing nut lock disclosed in Patel '163 is configured for use with a typical packing nut. Those conventional nuts have a series of “spanner holes,” that is, cylindrical passageways passing radially through their unthreaded end. The passageways are situated so that a rod, a so called “spanner” tool, may be inserted into the passageways as needed to tighten and loosen the nut. The lock itself has a main body with a cylindrical pin. Once the packing nut is tightened, the pin on the lock is placed in one of the spanner holes in the nut. The lock then is secured to the cylinder housing of the pump by a pair of set screws passing through the lock body.
It will be appreciated, however, that several operations are required to install and uninstall the lock. Additionally, a chain or cable preferably also must be used to ensure that the lock is not dropped or misplaced as the packing nut is removed and the packing serviced.
The access bore cover locking assembly disclosed in Patel '163 also is configured for use with a typical access bore cover. The cover is used to secure a plug or, as it is commonly called, a “suction valve cover” within the access bore. The cover is threaded so that it may be screwed into the access bore. The outer surface of the cover has a central polygonal opening, typically a hexagonal opening, into which an Allen wrench may be inserted to tighten and loosen the cover. The locking assembly includes a polygonal locking member which fits intimately into the central polygonal opening of the cover. Locking member has a central aperture, and it is secured to the suction valve cover by a reverse threaded bolt passing through the central aperture. The locking member also has a pair of threaded openings which allow set screw to be driven into engagement with the suction valve cover.
It will be appreciated, however, that the cover locking assembly prevents relative rotation of the suction valve cover, locking member, and bore cover, but does not prevent collective rotation of those components relative to the cylinder housing. As with the packing nut lock, the cover locking mechanism also requires several operations to install and uninstall, thus, complicating service of the pump valves. It also comprises various relatively small components that may easily be misplaced during service operations.
Such disadvantages and others inherent in the prior art are addressed by the subject invention, which now will be described in the following detailed description and the appended drawings.